Overview of a Pi 1160

7/31/2019 Overview of a Pi 1160

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Managing Pipeline System Integrity:

Introduction to API Standard 1160

Presented to

The Pipe Liners Club of TulsaTulsa, OK, January 21, 2002

By

Carl E. Jaske, Ph.D., [email protected]

CC Technologies, Dublin OH

Managing Pipeline System Integrity Slide 1

Background on CC Technologies

Mission: a team working together to solve corrosion,

materials, and fitness-for-service problems through

innovative engineering and applied research

Laboratories in Dublin, OH and Calgary, AB

Expertise in a variety of engineering disciplines:

metallurgical, materials, electrical, mechanical,

chemical, civil, ceramic, mechanics, aerospace, and

environmental geology

Services include research, testing, failure analysis,

engineering, consulting, pipeline integrity, fitness forservice, litigation support, specialty products, and

special-purpose engineering software

See http://www.cctechnologies.com


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ASME Pipeline Systems Subdivision

PSD objectives are as follows:

Promote technological progress and international

cooperation in pipeline systems engineering

Support education and timely, in-depth exchange of

information among researchers and engineers

Provide strong leadership and liaison, including

promotion of technical activities and conferences

Provide a public advocacy role for matters related

to pipelines

Promote the development of Codes and Standards

related to pipeline system design and safety

See http://www.asme.org/divisions/pipeline


International Pipeline Conference

PSD Sponsors the ASME International Pipeline

Conference & Exposition

IPC 2002 & IPE 2002 Will Be Held in Calgary,

Alberta, Canada, September 29 - October 3,

2002

Visit the IPC 2002 Web Site for Information:

http://www.asmeconferences.org/ipc02


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API Standard 1160

Managing System Integrity for Hazardous Liquid

Pipelines, API Standard 1160, First Edition,

November 2001 (See http://www.api.org)

Developed to Help Operators Comply with the

New Federal Rule onPipeline Integrity

Management in High Consequence Areas

(Information at http://www.cycla.com/opsiswc)

Operators Would Like to Have It Replace the

Non-Mandatory Appendix C of the Rule

This Is an ANSI Standard


Foreword: Regulatory Requirements 1

U.S. Operators Need to Understand

Requirements of 49 CFR 195.452 (Rule)

Pipeline Integrity Management in High

Consequence Areas (HCAs)

High population: 50,000 or 1,000 per sq. mile

Other populated area

Commercially navigable waterway

Unusually sensitive area (USA) to oil spills

Issued in November 2000, Effective March 31, 2002

API 1160 Includes Guidance for Compliance with

These Requirements


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Key Rule Requirements for Operators

Integrity Management Program Framework

Baseline Assessment Within 7 Years

In-line inspection(s)

or Hydrostatic pressure test

or Equivalent methodology

50% within first 3-1/2 years

Prioritize based on risk assessment

Periodically Re-assess Within 5 Years

Integrate Information from Other Relevant Sources

to Identify Potential Threats



Baseline Assessment Plan Must

Identify and locate all line segments that could

affect a HCA

Identify assessment method(s) for each segment

Include a schedule for completing assessments

Explanation of methods and risk factors used

Available for DOT OPS review

Maintain Written Integrity Management Program

Conduct Analyses to Integrate Information (7) Review of Results and Analysis by a Qualified

Person


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Schedule Repairs and Mitigative Actions (9)

Identify and Evaluate (8) Additional Preventive and

Mitigative Measures (10)

Measure the Performance of Effectiveness of the

Integrity Management Program (13)

API 1160 Is Organized to Help Operators of

Hazardous Liquids Pipelines Satisfy the New

HCA Rule

It Can Be Applied to Other Areas As Well; ManyOperators Wish toRaise the Bar


Outline of API 1160 (1-8)

1 Introduction

2 Scope

3 References

4 Terms, Definitions, and Acronyms

5 Integrity Management Program

6 High Consequence Areas

7 Data Gathering, Review, and Integration

8 Risk Assessment Implementation


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Outline of API 1160 (9-14)

9 Initial Baseline Assessment Plan Development

and Implementation

10 Mitigation Options

11 Revision of the Integrity Management Plan

12 Integrity Management of Pipeline Pump

Stations and Terminals

13 Program Evaluation

14 Managing Change in an Integrity Program


Outline of API 1160 (Appendices)

A Anomaly Types, Causes, and Concerns

B Repair Strategies

C Standard Data Fields for Tracking Pipeline

Releases

D Standard Data Fields for Pipeline

Infrastructure Information

This standard received extensive peer review and

was developed and revised following the ANSIprocess.


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Introduction

Purpose and Objectives Goal of Incident-Free Pipeline Operation

Improve Safety of Pipeline Systems

Guiding Principles Integrity Is Built in From the Beginning

Use Trained People and Defined Processes to

Operate Maintained Facilities

IM Program Must Be Flexible

Integrate Information

Risk Assessment Is Key and Continuous

Understand and Utilize New Technology

Third-Party Evaluation of IM Systems


Scope, References, and

Terms, Definitions, and AcronymsApplicable to Pipeline Systems Used to Transport

Hazardous Liquids; Principles Applicable to

All Pipeline Systems

List of Documents Referred To in the Standard

Explanation of Terms, Definitions, and Acronyms

Used in the Standard


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Integrity Management Program

Identify Potential

Pipeline Impact to

HCAs (Sectio n 6)

Initial Data Gathering,

Review, and Integration

(Section 7)

Initial RiskAssessment (Section 8)

Develop Baseline

Plan (Section 9)

Perform Inspection

and/orMitigation (Section 10)

Revise Inspection

and Mitigation

Plan (Section 11)

Evaluate

Program(Section 13)

Reassess

Risk (Section 8)

Update,

Integrate, and

Review Data(Section 7)

Managing

Change (Section 14)

Figure 5-1 illustrates

the framework of an

integrity management

program. Section 5

briefly describes each

of the remaining

sections of the

standard and shows

how they fit into theoverall IM process.


High Consequence Areas

Identify HCAs

Use National Pipeline Mapping System

Populated Areas and Navigable Waterways Are

Reasonably Well Defined

Unusually Sensitive Areas (USAs) May Be More

Difficult to Determine

OPS Database Is Not Complete

Available Data May Not Be Sufficient

Use HCA InformationDetermine Whether a Pipeline Will Affect a HCA

Document HCA Information


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Data Gathering, Review, and Integration

Data Sources

Identification and Location of Data

Identifying Data Needs

Locating Required Data

Establishing a Common Reference System

GPS Coordinates

Milepost, etc.

Data Collection - Table 7.1 Lists Common TypesData Integration - Key Element in IM Program


Integration Example: TPD Potential

Risk-Increasing Indicators Confirmation Activities

Patrol FrequencyDepth of CoverConstruction or Farm ActivityThird-Party Leak HistoryOne-Call Activity

In-Line Inspection (ILI)Dent SurveyThird-Party Leak HistoryPipe Exposure Reports

Question: What is the Likelihood of TPD at a SpecificLocation Along the Pipeline?


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Risk Assessment Implementation (1)

Developing a Risk Assessment Approach

Definition of Pipeline Risk

Consider Both Likelihood and Consequence

Estimating Risk Using Risk Assessment Methods

Characteristics of a Sound Risk Assessment

Approach

First Step in the Risk Assessment Process

Panel of Company Experts to Focus on PotentialProblems and Risk-Control Activities (Not Data)

Risk Assessment


Simplified Depiction of Risk

Consequences

Likelihood of Occurrence

High

Medium

Low

HighMediumLow

Lowest

RiskRegion

Highest

Risk

Region

River

Crossing With

High Traffic

Untilled

Meadow

Away fromWater


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Risk Assessment Implementation (2)

Core Risk Assessment Methodology Components

Identify and Gather Data for Risk Assessment

Validation and Prioritization of Risks

Risk Control and Mitigation

Continuous Risk Assessment

Risk assessment is not a one-time event.

There must be an established process to repeat risk

assessment at some operator-defined frequency.


Simplified Risk Assessment Hierarchy

Relative Risk

Consequences of

Failure

Likelihood of

Failure

DesignCorrosionTPD Service

Reliability

EnvironmentHealth and

Safety

Coating Type

Coating Inspection

Cathodic Protection

Soil Type...


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Sample Environmental Variables

RiskFactor

Variable Example Characteristics

ExternalCorrosion

Soil Type Clay Loam Sand Rock

InternalCorrosion

InternalWaterContent

None


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Some Variables Affecting Risk

Variable Variable Impact

Soil Type Resistivity impacts both current distribution and effectiveness ofthe cathodic protection (CP) system.

Texture can affect coating damage and premature corrosion. Acidity can attack coating and greatly increase corrosion rate. Although not preferred for above reasons, more stable soils

such as rock may be preferable in areas prone to groundmovement.

WallThickness

Increased value increases resistance to TPD and extends depthof pitting before a release occurs.

Increased value is preferred over casings at road crossings forCP.

Increased D/t ratios increase potential for damage from ground

movement.Weights/Hold-downs

Weights increase potential for crevice corrosion, coatingabrasion, and CP shielding.

Weights and hold-downs reduce risk of ground movementassociated with buoyancy issues and hill-side stability.


Initial Baseline Assessment Plan

Development and ImplementationInitial Baseline Plan

Pipeline Anomalies and Defects

Underground Pipeline Inspection Technology

Tutorial on ILI (Anomalies and Defects, Inspection

and Testing Technologies, Tools, Intervals, etc.)

Determination of Inspection Interval/Frequency

Hydrostatic Testing

Tutorial on Value, Limitations, and Intervals

Strategy for Responding to Anomalies Identifiedby In-Line Inspection (ILI)

Repair Methods


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Anomaly Types and Tools (Table 9-1)

Metal Loss Tools

Magnetic Flux Leakage (MFL)

Standard Resolution

High Resolution

Ultrasonic (Compression Wave)

Crack Detection Tools

Ultrasonic (Shear Wave)

Transverse MFL (TFI)

Geometry Tools Caliper

Mapping


Common Repair Methods (Table 9-2)

Repair Strategies Weld Metal Deposition Type A Sleeve

Type B Sleeve Composite Reinforcement

Hot Tap

Type of Anomaly 80% external wall loss

80% internal wall loss

>80% external wall loss

>80% internal wall loss Leaks, Arc Burns, and Girth Weld Flaws Dents With Stress Concentrators

Plain Dents


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Mitigation Options

Prevention of Third-Party Damage

Control of Corrosion

Detecting and Minimizing Unintended Pipeline

Releases

Pipeline Operating Pressure Reduction


Revision of the Integrity

Management PlanResult of Ongoing Data Review and Integration

Analysis of Inspection Data Usually Leads to

Mitigation Activities


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Integrity Management of Pipeline

Pump Stations and Terminals

Data Gathering

Concerns Unique to Mitigation Options

Mitigation Options


Program Evaluation

Performance Measures - Minimum of 10

Required

Performance Measurement Methodology

Measuring Performance Using Internal

Comparisons

Measuring Performance Using External

Comparisons

Audits

Performance Improvement


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Example Performance Measures

Reduce Total Volume from Unintended Releases

by a Specific Percent, Ultimate Goal of Zero

Reduce Total Number of Unintended Releases (5-

Gal. Threshold) by Specific Percent, Ultimate

Goal of Zero

Develop a Measure Based on Operational Events

That May Affect Integrity (e.g., unplanned

valve closures, SCADA outages, etc.)

Develop a Measure to Show That IM Program

Reduces Risk Over Time


Managing Change in

an Integrity ProgramRecognizing Changes That Affect the Integrity

Program

Updating the Pipeline Integrity Program


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Summary - 1

API Standard 1160 Is a Holistic Tool for

Planning, Implementing, Evaluating, and

Modifying an Integrity Management Program

Successful Programs Look Broadly at Reducing

Risks Through Risk Assessment and Analyses

Integrity Management Is Important to a

Companys Bottom Line and Reputation, So

API 1160 Address Operators Needs First

Risk Reduction, Not Regulatory Compliance, Is

the Goal of Integrity Management Programs


Summary - 2

Data Integration Is Essential, a Mechanism for

Integrating Information Must Be Incorporated

Into the Integrity Management Program

A Robust High-Quality Program Requires More

Than Just Regulatory Compliance

New Parallel Guideline onLiquid Pipeline

Security Program Is Being Developed by API

Peer Review Draft Issued December 12, 2001 Comments Due by End of January 2002


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References

1.Managing System Integrity for Hazardous

Liquid Pipelines, API Standard 1160, First

Edition, November 2001, American Petroleum

Institute, Washington, D.C.

(http://www.api.org)

2. M. Matheson, F. Fischer, and F. Gonzales,New

API standard to promote integrity for liquid pipe

lines, Pipe Line & Gas Industry, August 2001,

pp. 33-38. (http://www.pipe-line.com)

Overview of a Pi 1160

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